Time-lapse seismic signal analysis for enhanced oil recovery at Cranfield CO2 sequestration site, Cranfield field, Mississippi

2013 ◽  
Vol 1 (2) ◽  
pp. T157-T166 ◽  
Author(s):  
Julie Ditkof ◽  
Eva Caspari ◽  
Roman Pevzner ◽  
Milovan Urosevic ◽  
Timothy A. Meckel ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Time Lapse ◽  
Seismic Signal ◽  
Injection Well ◽  
Saturation Curve ◽  
Seismic Surveys ◽  
Seismic Amplitude ◽  
The Difference ◽  
Seismic Volumes ◽  
4D Seismic

The Cranfield field in southwest Mississippi has been under continuous [Formula: see text] injection by Denbury Onshore LLC since 2008. Two 3D seismic surveys were collected in 2007 and 2010. An initial 4D seismic response was characterized after three years of injection, where more than three million tons of [Formula: see text] remain in the subsurface. This interpretation showed coherent seismic amplitude anomalies in some areas that received large amounts of [Formula: see text] but not in others. To understand these effects better, we performed Gassmann substitution modeling at two wells: the 31F-2 observation well and the 28-1 injection well. We aimed to predict a postinjection saturation curve and acoustic impedance (AI) change through the reservoir. Seismic volumes were cross-equalized, well ties to seismic were performed, and AI inversions were subsequently carried out. Inversion results showed that the change in AI is higher than Gassmann substitution predicted for the 28-1 injection well. The time-lapse AI difference predicted by the inversion is similar in magnitude to the difference inferred from a time delay along a marker horizon below the reservoir.

Fluid dynamics at the base of hydrate-bearing sediments at the Vestnesa Ridge inferred from 5 years of high-resolution 4D seismic surveying

2020 ◽  
Author(s):  
Malin Waage ◽  
Stefan Bünz ◽  
Kate Waghorn ◽  
Sunny Singhorha ◽  
Pavel Serov
Keyword(s):  
High Resolution ◽  
Gas Hydrate ◽  
Seismic Data ◽  
Time Lapse ◽  
Stability Zone ◽  
Seismic Surveys ◽  
Free Gas ◽  
4D Seismic ◽  
Hydrate Bearing Sediments ◽  
Hydrate Stability

<p>The transition from gas hydrate to gas-bearing sediments at the base of the hydrate stability zone (BHSZ) is commonly identified on seismic data as a bottom-simulating reflection (BSR). At this boundary, phase transitions driven by thermal effects, pressure alternations, and gas and water flux exist. Sedimentation, erosion, subsidence, uplift, variations in bottom water temperature or heat flow cause changes in marine gas hydrate stability leading to expansion or reduction of gas hydrate accumulations and associated free gas accumulations. Pressure build-up in gas accumulations trapped beneath the hydrate layer may eventually lead to fracturing of hydrate-bearing sediments that enables advection of fluids into the hydrate layer and potentially seabed seepage. Depletion of gas along zones of weakness creates hydraulic gradients in the free gas zone where gas is forced to migrate along the lower hydrate boundary towards these weakness zones. However, due to lack of “real time” data, the magnitude and timescales of processes at the gas hydrate – gas contact zone remains largely unknown. Here we show results of high resolution 4D seismic surveys at a prominent Arctic gas hydrate accumulation – Vestnesa ridge - capturing dynamics of the gas hydrate and free gas accumulations over 5 years. The 4D time-lapse seismic method has the potential to identify and monitor fluid movement in the subsurface over certain time intervals. Although conventional 4D seismic has a long history of application to monitor fluid changes in petroleum reservoirs, high-resolution seismic data (20-300 Hz) as a tool for 4D fluid monitoring of natural geological processes has been recently identified.<br><br>Our 4D data set consists of four high-resolution P-Cable 3D seismic surveys acquired between 2012 and 2017 in the eastern segment of Vestnesa Ridge. Vestnesa Ridge has an active fluid and gas hydrate system in a contourite drift setting near the Knipovich Ridge offshore W-Svalbard. Large gas flares, ~800 m tall rise from seafloor pockmarks (~700 m diameter) at the ridge axis. Beneath the pockmarks, gas chimneys pierce the hydrate stability zone, and a strong, widespread BSR occurs at depth of 160-180 m bsf. 4D seismic datasets reveal changes in subsurface fluid distribution near the BHSZ on Vestnesa Ridge. In particular, the amplitude along the BSR reflection appears to change across surveys. Disappearance of bright reflections suggest that gas-rich fluids have escaped the free gas zone and possibly migrated into the hydrate stability zone and contributed to a gas hydrate accumulation, or alternatively, migrated laterally along the BSR. Appearance of bright reflection might also indicate lateral migration, ongoing microbial or thermogenic gas supply or be related to other phase transitions. We document that faults, chimneys and lithology constrain these anomalies imposing yet another control on vertical and lateral gas migration and accumulation. These time-lapse differences suggest that (1) we can resolve fluid changes on a year-year timescale in this natural seepage system using high-resolution P-Cable data and (2) that fluids accumulate at, migrate to and migrate from the BHSZ over the same time scale.</p>

Time‐lapse (4-D) seismic monitoring of primary production of turbidite reservoirs at South Timbalier Block 295, offshore Louisiana, Gulf of Mexico

Geophysics ◽  
2000 ◽  
Vol 65 (2) ◽  
pp. 351-367 ◽  
Author(s):  
Tucker Burkhart ◽  
Andrew R. Hoover ◽  
Peter B. Flemings
Keyword(s):  
Reservoir Characterization ◽  
Water Saturation ◽  
Seismic Analysis ◽  
Time Lapse ◽  
Hydrocarbon Production ◽  
Seismic Surveys ◽  
Seismic Amplitude ◽  
Fluid Properties ◽  
Multiple Reservoir ◽  
Gas Drive

Two seismic surveys acquired over South Timbalier Block 295 field (offshore Louisiana) record significant differences in amplitude that are correlated to hydrocarbon production at multiple reservoir levels. The K8 sand, a solution‐gas‐drive reservoir, shows increases in seismic amplitude associated with gas exsolution. The K40 sand, a water‐drive reservoir, shows decreases in seismic amplitude associated with increases in water saturation. A methodology is presented to optimize the correlation between two seismic surveys after they have been individually processed (poststack) This methodology includes rebinning, crosscorrelation, band‐pass filtering, and cross‐equalization. A statistical approach is developed to characterize the correlation between the seismic surveys. This statistical analysis is used to discriminate seismic amplitude differences that record change in rock and fluid properties from those that could be the result of miscorrelation of the seismic data. Time‐lapse seismic analysis provides an important new approach to imaging hydrocarbon production; it may be used to improve reservoir characterization and guide production decisions.

Resistance Method to Determine Oil Saturation Factors Research

2013 ◽  
Vol 807-809 ◽  
pp. 2503-2507
Author(s):  
Jie Nan Dong ◽  
Xu Su ◽  
Lian Feng Liu ◽  
Hong Zhan Wei ◽  
Cheng Long Ning
Keyword(s):  
Oil Recovery ◽  
Measurement Techniques ◽  
Saturation Curve ◽  
Oil Saturation ◽  
Standard Curve ◽  
Oil Distribution ◽  
Remaining Oil ◽  
Measurement Experiment ◽  
The Difference ◽  
Crucial Part

Studying the distribution of the remaining oil is a crucial part in the process of developing oilfield. This study provides the further improvement of oil recovery rate with strong guarantee, and is a necessary method of developing further water controlling of individual reservoir oilfield. Saturation measurement techniques for remaining oil distribution research are particularly important. This paper describes the research of ways of measuring saturation in the resistance measurement experiment, the standard resistance - saturation curve and the factors influencing it. The results show that for different electrode installation, standard curve is mainly affected by the electrode distance. Standard curve is also greatly affected by water salinity, temperature and the difference in corespermeability.

Semiquantitative 4D seismic interpretation integrated with reservoir simulation: Application to the Norne field

2018 ◽  
Vol 6 (3) ◽  
pp. T601-T611
Author(s):  
Juliana Maia Carvalho dos Santos ◽  
Alessandra Davolio ◽  
Denis Jose Schiozer ◽  
Colin MacBeth
Keyword(s):  
Simulation Model ◽  
Reservoir Simulation ◽  
History Matching ◽  
Time Lapse ◽  
Seismic Signal ◽  
Seismic Interpretation ◽  
Production Forecast ◽  
Seismic Acquisition ◽  
Reservoir Simulation Model ◽  
4D Seismic

Time-lapse (or 4D) seismic attributes are extensively used as inputs to history matching workflows. However, this integration can potentially bring problems if performed incorrectly. Some of the uncertainties regarding seismic acquisition, processing, and interpretation can be inadvertently incorporated into the reservoir simulation model yielding an erroneous production forecast. Very often, the information provided by 4D seismic can be noisy or ambiguous. For this reason, it is necessary to estimate the level of confidence on the data prior to its transfer to the simulation model process. The methodology presented in this paper aims to diagnose which information from 4D seismic that we are confident enough to include in the model. Two passes of seismic interpretation are proposed: the first, intended to understand the character and quality of the seismic data and, the second, to compare the simulation-to-seismic synthetic response with the observed seismic signal. The methodology is applied to the Norne field benchmark case in which we find several examples of inconsistencies between the synthetic and real responses and we evaluate whether these are caused by a simulation model inaccuracy or by uncertainties in the actual observed seismic. After a careful qualitative and semiquantitative analysis, the confidence level of the interpretation is determined. Simulation model updates can be suggested according to the outcome from this analysis. The main contribution of this work is to introduce a diagnostic step that classifies the seismic interpretation reliability considering the uncertainties inherent in these data. The results indicate that a medium to high interpretation confidence can be achieved even for poorly repeated data.

Time-lapse image-domain tomography using adjoint-state methods

Geophysics ◽  
2013 ◽  
Vol 78 (4) ◽  
pp. A29-A33 ◽  
Author(s):  
Jeffrey Shragge ◽  
Tongning Yang ◽  
Paul Sava
Keyword(s):  
Seismic Velocity ◽  
Time Lapse ◽  
Velocity Estimation ◽  
Data Sets ◽  
Velocity Change ◽  
Image Domain ◽  
Adjoint State ◽  
The Difference ◽  
Monitor Image ◽  
4D Seismic

Adjoint-state methods (ASMs) have proven successful for calculating the gradients of the functionals commonly found in geophysical inverse problems. The 3D ASM image-domain tomography (IDT) formulation of the seismic velocity estimation problem highlights imperfections in migrated image volumes and, using appropriate penalty functions (e.g., differential semblance), forms an objective function that can be minimized using standard optimization approaches. For time-lapse (4D) seismic scenarios, we show that the 3D ASM-IDT approach can be extended to multiple (e.g., baseline and monitor) data sets and offers high-quality estimates of subsurface velocity change. We discuss two different penalty operators that lead to absolute and relative 4D inversion strategies. The absolute approach uses the difference of two independent 3D inversions to estimate a 4D model perturbation (i.e., slowness squared). The relative approach inverts for the model perturbation that optimally matches the monitor image to the baseline image — even if migrated energy is imperfectly focused. Both approaches yield good 4D slowness estimates; however, we assert that the relative approach is more robust given the ubiquitous presence of nonrepeatable 4D acquisition noise and imperfect baseline model estimates.

A case history of time-lapse 3D seismic surveys at Cold Lake, Alberta, Canada

Geophysics ◽  
2006 ◽  
Vol 71 (4) ◽  
pp. B93-B99 ◽  
Author(s):  
J. Helen Isaac ◽  
Don C. Lawton
Keyword(s):  
Oil Recovery ◽  
Time Lapse ◽  
Steam Injection ◽  
Production Cycle ◽  
3D Seismic ◽  
Data Set ◽  
Seismic Surveys ◽  
History Of ◽  
Interval Velocities ◽  
Cold Lake

Time-lapse 3D seismic surveys were acquired across a bitumen field at Cold Lake, Alberta, Canada, during a production cycle (1990) and a steam-injection cycle (1992) of a thermal-enhanced oil recovery (EOR) program. We observed changes in interval traveltime and amplitude distributions between the processed surveys. We interpret the increased traveltimes observed over most of the injection survey to be a result of lowered interval velocities in the reservoir, caused primarily by higher temperature and lower effective pressure. Reflection-strength variations within the reservoir are present in each data set and change spatially between the surveys. In general, we interpret the amplitude anomalies seen only on the production survey to be caused by local free gas and the amplitude anomalies seen only on the injection survey, which are close to the perforation depths, to be caused by thin, vertically restricted steamed zones.

Tupi Nodes pilot: A successful 4D seismic case for Brazilian presalt reservoirs

2021 ◽  
Vol 40 (12) ◽  
pp. 886-896
Author(s):  
Nathalia Martinho Cruz ◽  
José Marcelo Cruz ◽  
Leonardo Márcio Teixeira ◽  
Mônica Muzzette da Costa ◽  
Laryssa Beatriz de Oliveira ◽  
...  
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Oil And Gas ◽  
Feasibility Studies ◽  
Oil And Gas Industry ◽  
Time Lapse ◽  
Seismic Inversion ◽  
Carbonate Reservoirs ◽  
Ocean Bottom ◽  
4D Seismic

The oil and gas industry has established 4D seismic as a key tool to maximize oil recovery and operational safety in siliciclastic and low- to medium-stiffness carbonate reservoirs. However, for the stiffer carbonate reservoirs of the Brazilian presalt, the value of 4D seismic is still under debate. Tupi Field has been the stage of a pioneering 4D seismic project to field test the time-lapse technique's ability in monitoring production and water-alternating-gas (WAG) injection in the Brazilian presalt. Ocean-bottom node (OBN) technology was applied for the first time in the ultra-deep waters of Santos Basin, leading to the Tupi Nodes pilot project. We started with feasibility studies to forecast the presalt carbonate time-lapse responses. The minerals that constitute these carbonate rocks have an incompressibility modulus that is generally twice as large as those of siliciclastic rocks. This translates into discrete 4D signals that require enhanced seismic acquisition and processing techniques to be correctly detected and mapped. Consequently, two OBN seismic acquisitions were carried out. Time-lapse processing included the application of top-of-the-line processing tools, such as interbed multiple attenuation. The resulting 4D amplitude images demonstrate good signal-to-noise ratio, supporting both static and dynamic interpretations that are compatible with injection and production histories. To unlock the potential of 4D quantitative interpretation and the future employment of 4D-assisted history-matching workflows, we conducted a 4D seismic inversion test. Acoustic impedance variations of about 1.5% are reliably distinguishable beyond the immediate vicinity of the wells. These 4D OBN seismic surveys and interpretations will assist in identifying oil-bypassed targets for infill wells and calibrating WAG cycles, increasing oil recovery. We anticipate that studies of the entire Brazilian presalt section will greatly benefit from the results and conclusions already reached for Tupi Field.

4D PLANNING AND EXECUTION STRATEGIES FOR AUSTRALIAN RESERVOIR MONITORING PROJECTS

2006 ◽  
Vol 46 (1) ◽  
pp. 67
Author(s):  
A.S. Long ◽  
M. Widmaier ◽  
M.A. Schonewille
Keyword(s):  
Time Lapse ◽  
Seismic Signal ◽  
Reservoir Simulations ◽  
Reservoir Models ◽  
Processing Strategies ◽  
Reservoir Monitoring ◽  
Seismic Acquisition ◽  
4D Seismic ◽  
Interactive Visualisation ◽  
Time Acquisition

Time-lapse (4D) reservoir monitoring is in its infancy in Australia, but is on the verge of becoming a mainstream pursuit. We describe the 4D seismic acquisition and processing strategies that have been developed and proven elsewhere in the world, and customise those strategies for Australasian applications.We demonstrate how a multidisciplinary pursuit of real-time acquisition and processing Quality Control (QC) is an integral component of any 4D project. The acquisition and processing geophysicists must be able to understand all the factors contributing to the 4D seismic signal as they happen. Such an understanding can only arise through rigorous project QC and management using interactive visualisation technology. In turn, the production geologists and reservoir engineers will then receive 4D seismic products that can be robustly and confidently used for the construction of accurate reservoir models and the pursuit of reliable reservoir simulations and forecasts.

The problem of using normalized rms in a sliding window to compare seismic tracesDISCUSSIONOn: “Imaging the Aquistore reservoir after 36 kilotonnes of CO2 injection using distributed acoustic sensing.” Harris, K., White, D.J., Samson, C., 2017. Geophysics 82 (6), M81–M96and “Initial 4D seismic results after CO2 injection start-up at the Aquistore storage site.” Roach, L.A.N., White, D.J., Roberts, B., Angus, D., 2017. Geophysics 82 (3), B95–B107.

Geophysics ◽  
2021 ◽  
pp. 1-9
Author(s):  
Balazs Nemeth ◽  
Christian Escalante
Keyword(s):  
Sliding Window ◽  
Time Lapse ◽  
Co2 Injection ◽  
Storage Site ◽  
Seismic Surveys ◽  
Start Up ◽  
Distributed Acoustic Sensing ◽  
Difference Calculation ◽  
Difference Volume ◽  
4D Seismic

Two papers published in Geophysics use the normalized rms (NRMS) calculation in a sliding window to compare traces and to create a ‘difference nrms’ volume. The authors use the derived difference volume to show the presence of apparent time-lapse anomaly between two seismic surveys. In this discussion we point out that the used methodology does not allow a robust comparison of seismic traces. We recommend the use of simple amplitude difference calculation between volumes to show the presence of time-lapse anomalies, instead of the used methodology.

Integrated simulation to seismic and seismic reservoir characterization in a CO2 EOR monitoring application

2020 ◽  
Vol 39 (9) ◽  
pp. 668-678
Author(s):  
Alan Mur ◽  
César Barajas-Olalde ◽  
Donald C. Adams ◽  
Lu Jin ◽  
Jun He ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Reservoir Simulation ◽  
Seismic Data ◽  
Reservoir Characterization ◽  
Rock Physics ◽  
Time Lapse ◽  
Seismic Signal ◽  
Inversion Method ◽  
Data Sets ◽  
Production Effects

Understanding the behavior of CO2 injected into a reservoir and delineating its spatial distribution are fundamentally important in enhanced oil recovery (EOR) and CO2 capture and sequestration activities. Interdisciplinary geoscience collaboration and well-defined workflows, from data acquisition to reservoir simulation, are needed to effectively handle the challenges of EOR fields and envisioned future commercial-scale sites for planned and incidental geologic CO2 storage. Success of operations depends on decisions that are based on good understanding of geologic formation heterogeneities and fluid and pressure movements in the reservoir over large areas over time. We present a series of workflow steps that optimize the use of available data to improve and integrate the interpretation of facies, injection, and production effects in an EOR application. First, we construct a simulation-to-seismic model supported by rock physics to model the seismic signal and signal quality needed for 4D monitoring of fluid and pressure changes. Then we use Bayesian techniques to invert the baseline and monitor seismic data sets for facies and impedances. To achieve a balance between prior understanding of the reservoir and the recorded time-lapse seismic data, we invert the seismic data sets by using multiple approaches. We first invert the seismic data sets independently, exploring sensible parameter scenarios. With the resulting realizations, we develop a shared prior model to link the reservoir facies geometry between seismic vintages upon inversion. Then we utilize multirealization analysis methods to quantify the uncertainties of our predictions. Next, we show how data may be more deeply interrogated by using the facies inversion method to invert prestack seismic differences directly for production effects. Finally, we show and discuss the feedback loop for updating the static and dynamic reservoir simulation model to highlight the integration of geophysical and engineering data within a single model.

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